1. Field of the Invention
The present invention relates to the completion of a wellbore. More particularly, the invention relates to methods for completing a hydrocarbon wellbore that involve heating of circulating fluid to increase formation fracture pressure in the surrounding formation during drilling, cementing and completion operations.
2. Description of the Related Art
Hydrocarbon wells are formed by drilling a borehole in the earth, and then lining that borehole with steel casing in order to form a wellbore. After a section of earth has been drilled, a string of casing is lowered into the bore and temporarily hung therein from the surface of the well. Using apparatus known in the art, the casing is cemented into the wellbore by circulating cement into the annular area defined between the outer wall of the casing and the borehole.
It is common to employ more than one string of casing in a wellbore. In this respect, a first string of casing is set in the wellbore when the well is drilled to a first designated depth. The first string of casing is hung from the surface, and then cement is circulated into the annulus behind the casing. The well is then drilled to a second designated depth, and a second string of casing, or liner, is run into the well. The second string is set at a depth such that the upper portion of the second string of casing overlaps the lower portion of the first string of casing. The second liner string is then fixed or “hung” off of the existing casing by the use of slips which utilize slip members and cones to wedgingly fix the new string of liner in the wellbore. The second casing string is then cemented in the well. This process is typically repeated with additional casing strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing of an ever decreasing diameter.
It would be ideal to be able to drill a single, continuous bore into the earth that extends to a desired production zone without utilizing separate strings of casing. However, a variety of factors require that wellbores be formed in sequential stages. One such limiting factor is the need for weighted drilling fluid. Wells have historically been drilled by placing a column of weighted fluid, sometimes referred to as “drilling mud,” in the drill string. The drilling mud serves to overcome formation pore pressures encountered as the wellbore is formed through the earth formations. In this respect, fluid pressure in a wellbore is intentionally maintained at a level above the pore pressure of formations surrounding the wellbore. Pore pressure refers to the natural pressure of fluid within a formation. The hydrostatic fluid pressure of the drilling fluid must be kept below the fracture pressure of the formation to prevent the wellbore fluid from entering the formation. Exceeding fracture pressure can result in fracturing of the formation and loss of expensive drilling fluid into the formation. More importantly, lost circulation creates a risk to personnel on the rig floor, as the rig is now subject to a “kick” caused by formation pore pressures.
The drilling mud is circulated through the drill bit and up an annular area between the drill string and surrounding casing or formation. The circulation of fluids in this manner not only aids in the control of wellbore pressures, but also serves to cool and lubricate the drill bit and to circulate cuttings back up to the surface. However, the circulation of fluids also forms a hydrostatic head and a friction head in the annular region that combine to form an “equivalent circulation density,” or ECD. The use of drilling mud and the resulting ECD create an inherent limitation as to the depth at which any section of borehole may be drilled before it must be cased.
Conventionally, a section of wellbore is drilled to that depth where the combination of the hydrostatic pressure and friction head approaches the fracture pressure of the formation adjacent the bottom of the wellbore. At that point, casing is installed in the wellbore to isolate the formation from the increasing pressure before the wellbore can be drilled to a greater depth. In the past, the total well depth was relatively shallow and casing strings of a decreasing diameter were not a big concern. Presently, however, with extended reach drilling (ERD) wells, so many casing strings are necessary that the fluid path for hydrocarbons at a lower portion of the wellbore becomes very restricted. In other instances, deep wellbores are impossible due to the number of casing of strings necessary to avoid fracturing the formation and to complete the wellbore. FIG. 8 illustrates this point, which is based on a deepwater Gulf of Mexico example.
In FIG. 8, dotted line A shows pore pressure gradient, and line B shows fracture gradient of the formation, which is approximate to the pore pressure gradient but higher. Circulating pressure gradients of 15.2-ppg drilling fluid in a deepwater well is shown as line C. The circulation density line C is not parallel to the hydrostatic gradient of the fluid (line D). Safe drilling procedure requires circulating pressure gradient (line C) to lie between pore pressure and fracture pressure gradients (lines A and B). However, as shown in Graph 1, circulating pressure gradient of 15.2-ppg drilling fluid in this example extends above the fracture gradient curve at some point where fracturing of formation becomes inevitable. In order to avoid this problem, a casing must be set up to the depth where line C meets line B within predefined safety limit before proceeding for further drilling. For this reason, the drilling program for a GOM well called for as many as seven casing sizes, excluding the surface casing (Table 1).
TABLE 1Planned casing program for GOM deepwater well.Casing sizePlanned shoe depth(in.)(TVD-ft)(MD-ft)303,0423,042204,2294,229165,5375,53713-3758,0168,01611-3/813,62213,690 9-5/817,69618,171 724,31925,145 525,77226,750
Attempts have been made to reduce the pressure of fluid in a circulating wellbore. However art approaches have been directed primarily towards reducing pressure at the bit to facilitate the movement of cuttings to the surface. In a prior art patent, a redirection apparatus is shown which vents fluid from an interior of a tubular to an exterior thereof. While this device stirs up and agitates wellbore fluid, it does not provide any meaningful lift to the fluid in order to reduce the pressure of fluid there below.
A similar issue may be confronted during a cementing operation. In this respect, the act of sequentially circulating various fluids through a liner and back up the annulus necessarily creates radial pressures on the surrounding borehole. The presence of a full annulus additionally creates additional hydrostatic pressure. Moreover, the circulation of such fluids creates a “friction head,” as described above. Various fluids may be circulated during a cementing operation, including mud, water and the cement itself. These factors also may limit the length of liner that can be cemented in one completion stage.
There is a need, therefore, for a method of completing a wellbore that reduces the number of casing strings (liners) needed. In addition, there is a need for a method of completing a wellbore that causes the formation to tolerate a higher equivalent circulation density (ECD) of the drilling fluid. Further, there is a need for a method of completing a wellbore that utilizes a fluid heating apparatus to heat fluids as they are circulated during drilling and, in addition, which adds energy to fluids in the annular region. There is yet a further need for a method to reduce or to prevent differential sticking of a work string in a wellbore as a result of fluid loss into the wellbore. Still further, there is a need for a tool that may be employed that inhibits formation fracturing or fluid loss during a cementing operation. Some of these objects and others are met by various embodiments of the methods of the present invention.